This invention relates to a method of reducing the permeability of the more permeable zones of an underground formation and in particular, such formations containing hydrocarbons.
Variations in permeability and reservoir heterogenies can significantly affect the sweep efficiency of oil recovery processes. The efficiency of these processes is dependent upon (1) microscopic displacement efficiency and (2) volumetric sweep efficiency. A small improvement in volumetric sweep efficiency can have a significant impact on the overall efficiency of an oil recovery process.
Several methods for improving reservoir sweep efficiency through permeability modification have been proposed. In recent years there has been a considerable interest in the application of cross-linked polymer technology to alleviate the problems associated with reservoir heterogeneity. Two processes are used commercially to cross-link polyacrylamides and biopolymers. Both processes are based upon the controlled-release of multivalent metal ions which results in polymer cross-linking. But the application of polymer technology for permeability modification has several limitations which have yet to be fully addressed. Problems with polymer (also known as gelled-polymer) treatments include (1) limited depth penetration, (2) loss of injectivity, (3) problems controlling polymer gellation rates, (4) loss of viscosity caused by shear degradation, (5) polymer precipitation and degradation under reservoir conditions, (6) environmental concerns over crosslinking agents, and (7) in some cases, undesirable polymer-surfactant interaction.
U.S. Pat. No. 4,194,563 discloses a method for recovering petroleum from a subterranean formation having at least two different permeabilities. After a water or surfactant flood, an aqueous treating liquid is injected into the formation. The aqueous treating liquid has a viscosity no more than twice that of water, contains at least one surfactant, and is capable of producing a stable viscous oil-in-water emulsion with petroleum present in the zone of the formation being treated. After the injection of treating liquid, the face of the formation exposed to the injection well is flushed with an emulsion-breaking liquid comprising an alcohol in order to break any emulsion which has formed in the low permeability zone at the formation face. Following the flushing step a second surfactant containing oil-displacing fluid is injected into the formation to displace petroleum from the low permeability zones which have not been blocked by the emulsion. Preferably the aqueous treating liquid is comprised of an emulsifying surfactant mixture of an alkylpolyalkoxyalkylene sulfonate or alkylarylpolyalkoxyalkylene sulfonate and a water-soluble organic sulfonate such as an alkyl sulfonate, an alkyl aryl sulfonate or a petroleum sulfonate. Additionally the treating liquid may contain an ethoxylated or an ethoxylated and propoxylated non-ionic surfactant of a specific formula.
U.S. Pat. No. 4,296,811 discloses a method for improving the sweep efficiency of a post-primary oil recovery process in an oil bearing subterranean formation containing a high concentration of divalent ions in the connate water. The method involves injecting a surfactant system comprised of a predominantly sodium chloride brine, a petroleum sulfonate surfactant, a cosurfactant and no more than 1% oil. The surfactant system forms a macro-emulsion in situ to selectively plug the more permeable zones of the subterranean formation. The cosurfactant is selected from a group consisting of amides, amines, esters, aldehydes, and ketones containing 1-20 carbon atoms and alcohols containing 4-7 carbon atoms. The preferred cosurfactant is isobutyl alcohol.
U.S. Pat. No. 4,745,976 discloses a method for partially or completely blocking the high permeability regions of a reservoir. The technique is based upon the ability to induce phase changes in surfactant solutions by changing counterions or by adding small quantities of different surfactants. An aqueous solution of an ionic surfactant may have a viscosity only slightly different from brine but an increase in the salt concentration or addition of a multivalent counterion can cause the surfactant to form a solid precipitate or form a gel-like structure of high viscosity. In the method of U.S. Pat. No. 4,745,976, a first surfactant solution is injected into the formation followed by a water-soluble spacer fluid followed by a second surfactant solution. In situ mixing of the two surfactant solutions is affected by the tendency of different surfactant types to travel at different velocities through the reservoir. The compositions of the first and second surfactants solutions are chosen so that upon mixing a precipited or gel-like structure will form blocking the high permeability zone of the reservoir.
There are however continuing problems with the known permeability reduction methods. In particular, known methods do not permit further propagation of the permeability reduction slug (e.g., polymer and/or surfactant) after initial setting. Known methods are also prone to injectivity loss. Additionally, methods which require in situ mixing and/or contact of various fluids (such as the mixing of two surfactant solutions or the mixing of a surfactant and a brine) are problematic. For example, the fluids may contact at the wrong location in the reservoir, leading to premature gelling. There is also the likelihood of partial or incomplete contact of the fluids resulting in insufficient plugging or blocking of high permeability zones.